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Stimulation Using Hydraulic Fracturing

Hydraulic Fracturing

The first commercial application of hydraulic fracturing as a well treatment technology designed to stimulate the production of oil or gas likely occurred in either the Hugoton field of Kansas in 1946 or near Duncan, Okla., in 1949. In the following decades, the use of hydraulic fracturing has developed into a routine technology that frequently is used in the completion of gas wells, especially those drilled into unconventional reservoirs such as tight shale.

The process involves pumping fluid into a formation under sufficient pressure to create fractures in the rock matrix; allowing oil or gas to flow through the fractures more freely to the wellbore. By creating new pathways, hydraulic fracturing can exponentially increase oil and gas flow to the well. For example, a single fracture job can increase the pathways available for fluid migration in a formation by as much as 270 times in a vertical well – and much more in a horizontal well.

The process of hydraulic fracturing can be a critical component of well development because, without it, there may be insufficient flow pathways for oil or gas to get to the wellbore. The only alternative to fracturing the producing formations in reservoirs with low permeability would be to drill more wells in an area. However, given the costs of drilling, the risks associated with creating multiple new vertical pathways for fluid migration, and the fact that it could take very large numbers of wells located within a very small area to equal the production of even a single hydraulically fractured well, this alternative is neither physically nor economically desirable.

Fracture Fluids
Fracture fluids may be based on either acid, gel, water or oil. Most fracturing work is conducted using water-based fluid. In addition to water, fracture fluids can contain a wide array of additives, each designed to serve a particular function. For example, in hydraulic fracturing of deep shale gas zones, the water commonly is mixed with a friction reducer to lessen the resistance of the fluid moving through the casing; biocides to prevent  bacterial growth; scale inhibitors to prevent buildup of scale; and proppants, such as sand or ceramic beads to hold the fractures open. This type of fracturing process often is referred to as a slickwater fracture. It is the use of additives, such as those listed above, that has raised one of the concerns about hydraulic fracturing. A small number of potential fracture fluid additives, such as benzene, ethylene glycol and naphthalene have been linked to negative health effects at certain exposure levels. However, most additives contained in fracture fluids, including sodium chloride, potassium chloride and diluted acids, present low to very low risks to human health and the environment.

The best way to eliminate concern would be to use additives that are not associated with human health effects. While desirable, this is not yet possible in the case of some additives because the alternatives do not always have the properties necessary to provide the same degree of effectiveness as more traditional constituents. However, with respect to diesel fuel, which was cited as a principal constituent of concern by the Oil and Gas Accountability Project because of its relatively high benzene content, an agreement was reached to discontinue its use as a fracture fluid media in zones that qualify as underground sources of drinking water (USDWs).

The discontinuation of diesel fuel use resulted from an effort that began at the 2002 annual meeting of the Ground Water Protection Council (GWPC). At that meeting, the GWPC board of directors passed a resolution calling for a ban on the use of diesel fuel in the hydraulic fracturing of coalbed methane (CBM) wells where drinking water sources were present. This was a landmark event that led to the development of a 2003 Memorandum of Agreement between BJ Services Co., Halliburton Energy Services Inc., Schlumberger Technology Corp. and the Environmental Protection Agency. In the memorandum, these companies, which were estimated to account for up to 95 percent of all fracture jobs conducted in the United States, agreed to eliminate diesel fuel in hydraulic fracturing fluids injected into CBM production wells in USDWs within 30 days of signing the agreement. In 2008, the GWPC conducted a follow-up survey that found that in 25 states with potential coalbed methane production, the use of diesel fuel to hydraulically fracture coal beds that are USDWs was not occurring. Regardless of relative concentration, it is important that additives be prevented from entering ground water and creating unnecessary risks.

Exposure Pathways
Some reports critical of the hydraulic fracturing process have cited the exposure effects of additives that can be contained in hydraulic fracturing fluids without considering their relative availability via exposure pathways. For example, one study found that depending upon the design of the fracture job and the specific formation dynamics involved, anywhere from 30 percent to 70 percent of fracturing fluids are returned to the surface through the well. The unrecovered treatment fluids typically are trapped in the fractured formation via various mechanisms such as pore storage and stranding behind healed fractures, thus isolating them from ground water. The risk of endangerment to ground water is further reduced by other physical factors such as:

  • implementation of state well construction requirements;
  • vertical distance between the fractured zone and ground water;
  • presence of other zones between the fractured zone and the deepest ground water zone that may readily accept fluid; and
  • presence of vertically impermeable formations between the fractured zone and the deepest ground water zone, which act as geologic barriers to fluid migration.


Additionally, proper surface fluid-handling methods can significantly decrease the likelihood of environmental harm from, or human exposure to, hydraulic fracturing fluids. For example, once hydraulic fracturing fluids return to the surface, they typically are stored in tanks or lined pits to isolate them from soils and shallow ground water zones.

The ultimate fate of hydraulic fracturing fluids returned to the surface often is determined by the availability of treatment and disposal technologies such as on-site or municipal treatment facilities and injection wells. Underground disposal via injection wells is the most common method of disposal for used fracture fluid. However, prior to disposal, fluids sometimes are treated and re-used in subsequent fracturing. On-site treatment and surface discharge, though rarely used, also is a disposal option. Treatment in municipal wastewater facilities also is sometimes conducted, provided the fluid will not cause the facility to violate a drinking water standard. The use of these techniques reduces the risk of endangerment to water.

Until effective alternatives to other, traditional additives are in wide use, the best way to protect ground water is to isolate hydraulic fracture fluids from ground water zones. Consequently, the primary mode of regulating hydraulic fracturing involves the application of well construction requirements designed to seal the wellbore and prevent the movement of fluids into ground water.

Isolation Techniques
Since ground water contamination resulting from the flowback of fracture fluids returned to the surface through casing would require simultaneous failures of multiple barriers of protection, such as casing strings and cement sheaths, the risk profile for such an event is low. Therefore, the greatest risk of contamination of ground water by fracture fluids comes from the potential for fluids to migrate upward within the casing/formation annulus during the fracturing process. The most effective means of protecting ground water from upward migration in the annulus is the proper cementation of well casing across vertically impermeable zones and ground water zones. Proper cementation creates the hydraulic barriers that prevent fluid incursion into ground water. The amount and placement of cement needed for this purpose will vary depending upon several factors including:

  • size of the casing/wellbore annulus;
  • quality of cement;
  • depth, thickness and vertical permeability of formations between the fractured zone and ground water; and
  • distance between the fractured zone and ground water.


In a survey of 25 state oil and gas regulatory agencies conducted by the GWPC, 24 state programs said they had not recorded any complaints of contamination to a USDW that the agency could attribute to hydraulic fracturing of coalbed methane zones. Since this survey was conducted, several citizens have alleged that their ground water has been contaminated by the practice of hydraulic fracturing. Most of these complaints appear to be related to hydraulic fracturing of coalbed methane zones, which were in relatively close proximity to USDWs.

Depending upon the geologic setting, CBM wells typically, though not always, are shallower than conventional oil and gas wells and many unconventional shale gas zones. In general, the amount of vertical separation between an oil-and-gas-producing formation and the deepest ground water zone in many parts of the country can be several thousand feet, while the separation of coalbed methane zones to ground water sometimes is only a few hundred feet or less. In some cases, the CBM zones themselves may qualify as USDWs. Regardless, it is not unreasonable to conclude that the risk of fracture fluid intrusion into ground water from the hydraulic fracturing of deeper conventional and unconventional oil and gas zones could be considered very low because:

  • there often is significant vertical separation between the fractured zone and ground water zones, especially in the majority of deep shale gas play;
  • well construction requirements in most states include provisions for cementation above producing zones and across ground water zones;
  • frequently, there are layers of rock between the fractured zone and ground water zones that are capable of accepting fluid under pressure, which would lower the available fluid that could reach a ground water zone;
  • frequently, there are layers of rock between the fractured zone and ground water zone through which vertical flow is restricted, thus serving as a hydraulic barrier to fluid migration; and
  • the use of advanced computer modeling in fracture design has increased the ability to predict the three-dimensional geometry of fracturing, which lowers the likelihood of a fracture job extending into an unintended zone.

Courtesy ND


This article is provided through the courtesy of the U.S. Department of Energy’s National Energy Technology Laboratory.



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